Method for Gas Zone Detection Using Sonic Wave Attributes

ABSTRACT

A method for determining on a real time logging while drilling (LWD) basis gas within earth formations traversed by a borehole. Continuous LWD acoustic measurements are recorded and processed including coherent energy and attenuation attributes to detect downhole gas zones and kick during drilling operations.

TECHNICAL FIELD

This application is a continuation application of U.S. patentapplication Ser. No. 11/964,731, filed Dec. 27, 2007.

This invention relates to wireline and logging-while-drillingmeasurement of sonic wave component attributes and use of thatinformation for determining gas zones within a formation and/or kickdetection. More specifically, this invention is directed to determiningtraditional compressional slowness (DTc), shear slowness (DTs) andStoneley slowness (DTst) and in addition determining attributes ofcoherent energy (CE) and attenuation (ATT) for use in detecting the realtime presence of gas in a formation and/or kick detection.

BACKGROUND OF THE INVENTION

In the oil and gas industry acoustic tools are used to provideoperationally significant information about borehole and formationattributes adjacent the tools such as compressional, shear and Stoneleyslowness. These attributes are analyzed for determining, inter alia, therate of flow of a hydrocarbon (gas or oil) out of a producing boreholein the hydrocarbon production industry. This critical informationfundamentally depends on permeability of the formation, viscosity of thehydrocarbon and the existence of fractures. Collecting and recordingthis information on a delayed or real time basis is known as welllogging.

Evaluation of physical properties such as pressure, temperature andwellbore trajectory in three-dimensional space and other boreholecharacteristics while extending a wellbore is known asmeasurements-while-drilling (MWD) and is standard practice in manydrilling operations. MWD tools that measure formation parameters such asresistivity, porosity, sonic velocity, gamma ray, etc. of a formationare known as logging-while-drilling (LWD) tools. An essential formationparameter for determination in a drilling operation is the existence ofgas deposits or zones in a formation, on a real time basis. Similarly,early detection of kick is essential information for conducting safe andefficient drilling operations.

For the above and other reasons, the oil industry has developed acousticwell logging techniques that involve placing an acoustic tool within awell bore to make measurements indicative of formation attributes suchas compressional slowness (DTc), shear slowness (DTs) and Stoneleyslowness (DTst). Sonic logs can be used as direct indications ofsubsurface properties and in combination with other logs and knowledgeof subsurface properties can be used to determine subsurface parameters,such as those related to borehole structure stability, that can not bemeasured directly. Early efforts in this connection were reported byRosenbaum in “Synthetic Microseismograms: Logging in Porous Formations”,Geophysics, Vol. 39, No. 1, (February 1974) the disclosure of which isincorporated by reference as though set forth at length.

Acoustic logging tools typically include a transmitter and an array ofaxially spaced acoustic detectors or receivers. These tools are operableto detect, as examples, formation compressional waves (P), formationshear waves (S) and Stoneley waves. These measurements can be performedfollowing drilling or intermediate drill string trips by wirelinelogging operations. In wireline logging, sonic monopole tools can beused to measure compression waves (P) and shear waves (S) in fastformations. In addition to wireline logging, techniques have beendeveloped where piezoelectric transmitters and hydrophone receivers areimbedded within the walls of drill string segments so that sonic LWDoperations can be performed.

Early wireline and LWD and sonic data processing techniques developed bythe Schlumberger Technology Corporation such as aslowness-time-coherence (STC) method is disclosed in U.S. Pat. No.4,594,691 to Kimball et al. entitled “Sonic Well Logging” as well as inKimball et al. “Semblance Processing of Borehole Acoustic Array Data,”Geophysics, Vol. 49, No. 3 (March 1984). This method is most useful fornon-dispersive waveforms (e.g. monopole compressional and shear headwaves). For processing dispersive waveforms a dispersiveslowness-time-coherence (DSTC) is preferred. This process is disclosedin U.S. Pat. No. 5,278,805 to Kimball entitled “Sonic Well LoggingMethods and Apparatus Utilizing Dispersive Wave Processing.” Thedisclosures of these patents, of common assignment with the subjectapplication, as well as the noted Geophysics publication authored by anemployee of Schlumberger are hereby also incorporated by reference.

Sonic wireline tools, such as a Dipole Shear Sonic Imager (DSI—trademarkof Schlumberger) and Schlumberger's Sonic Scanner generally have amulti-pole source. A multi-pole source may include monopole, dipole andquadrupole modes of excitation. The monopole mode of excitation is usedtraditionally to generate compressional and shear head waves in loggingoperations such that formation compressional and shear slowness logs canbe obtained by processing the head wave components. The head wavecomponents are non-dispersive and are generally processed byslowness-time-coherence (STC) methods as discussed in the SchlumbergerKimball et al. '691 patent and Vol. 49 Geophysics article noted above.

The slowness-time-coherence (STC) method is employed to process themonopole wireline or LWD sonic waveform signals for coherent arrivals,including the formation compressional, shear and borehole Stoneleywaves. This method systematically computes the coherence (C) of thesignals in time windows which start at a given time (T) and have a givenwindow move-out slowness (S) across the array. The 2D plane C(S,T) iscalled the slowness-time-plane (STP). All the coherent arrivals in thewaveform will show up in the STP as prominent coherent peaks. Thecompressional, shear and Stoneley slowness (DTc, DTs, and DTst) will bederived from the attributes of these coherent peaks.

Traditionally, the attributes associated with the wave components foundin the STP are the slowness, time and the peak coherence values. Thesethree attributes are used in a labeling algorithm, discussed below, todetermine the compressional, shear and Stoneley slowness from all of theSTP peak candidates. These attributes can also be used for qualitycontrol purposes.

Although determining traditional attributes has been highly effective inthe past a need exists for enhancing information that can be determinedfrom traditional wave form attributes and determining additionalattributes such as coherent energy and attenuation that can be used todetermine the existence of a gas zone and/or kick detection, on a realtime basis, during LWD operations.

SUMMARY OF THE INVENTION

The methods of the subject invention includes the slowness, time,coherence attributes and in addition the attributes of coherent energyand attenuation. The combination of these attributes can beadvantageously used for detecting with well logging and logging whiledrilling operations formation gas zones and kick detection on a realtime basis.

THE DRAWINGS

Other aspects of the present invention will become apparent from thefollowing detailed description of embodiments taken in conjunction withthe accompanying drawings.

FIG. 1 is a schematic of a typical derrick and a logging-while-drilling(LWD) system where a drill string is positioned within a borehole and awell logging segment near a drill bit is shown within a borehole;

FIG. 2 a is an enlarged diagram of a logging tool within a boreholetaken at a location above a drill bit within a borehole of FIG. 1;

FIG. 2 b is a schematic cross-sectional view of a quadrupole sonictransmitter taken from the LWD segment shown in FIG. 2 a.

FIG. 2 c is a schematic cross-sectional view of a quadrupole receiverfrom a stack of receivers of the LWD tool shown in FIG. 2 a;

FIG. 3 is a schematic diagram disclosing traditional sonic wavetechnology including a representative transmitter, receiver andcompressional waves, shear waves and Stoneley sonic waves;

FIG. 4 is a synthetic waveform illustrating waveform attributecomputation;

FIG. 5 a is a graph depicting a combination of an increase incompressional slowness (DTc) along with a decline in compressional toshear velocity (Vp/Vs) indicative of the presence of gas;

FIG. 5 b is a graph depicting the pattern of compressional and shearattenuation (ATTc and ATTs) when a gas zone is encountered;

FIG. 5 c is a graph showing a pattern of shear and compressional energy(CEs and CEc) indicative of when a driller is about entering into a gasbearing formation;

FIG. 6 a is a graph illustrating the effect on Stoneley slowness (DTst)of the influx of gas in a well bore;

FIG. 6 b is a graphic illustration of the effect on a ratio of Stoneleyslowness (DTst) to shear slowness (DTs) due to an influx of gas within aborehole;

FIG. 6 c is a graph showing a baseline Stoneley coherent energy (CEst)and a baseline Stoneley attenuation (ATTst) and the effect due to aninflux of gas useful for kick detection;

FIG. 7 is an illustrative flow diagram for gas zone detection inaccordance with one embodiment of the subject invention;

FIG. 8 is an illustration of Gas Response Indicator (GRI) and Gas Flag(GF) as a function of Depth or Time for gas zone detection;

FIG. 9 is a flow diagram for sonic attributes kick detection within abore hole in accordance with another embodiment of the invention; and

FIG. 10 is an illustration of Gas Response Indicator (GRI) and Kick Flag(KF) as a function of depth or time to provide warning of an imminentgas kick event.

DETAILED DESCRIPTION

Turning now to the drawings, the subject invention is directed to theconcept of sonic measurements and systematically determining formationattributes of compressional, shear, and Stoneley slowness (DT) coherentenergy (CE) and attenuation (ATT) and using the information on a realtime basis to detect the presence of a gas zone or kick within aborehole.

Context of the Invention

FIG. 1 discloses a drilling derrick 100 positioned over a well hole 102being drilled into an earth formation 104. The drilling derrick has theusual accompaniment of drilling equipment including a processor 106 andrecorder 108 of the type used for measurements-while-drilling (MWD) orlogging-while-drilling (LWD) operations. A more detailed disclosure ofconventional drilling equipment of the type envisioned here is describedin Schlumberger's Wu et al published application No. 2006/0120217 thedisclosure of which is incorporated by reference as though set forth atlength.

The borehole is formed by a drill string 110 carrying a drill bit 112 atits distal end. The drill bit crushes its way through earth formationsas the drill string is rotated by drilling equipment within the drillingderrick. The depth of a well will vary but may be as much at 25,000 feetor more in depth.

Turning to FIGS. 2 a-2 c a quadrupole acoustic shear wave LWD toolsegment 114 is shown in a degree of schematic detail. A more detaileddiscussion of a LWD tool of this type can be seen in Hsu et al.Publication No. US 2003/0058739 of common assignment with the subjectapplication. The disclosure of this entire publication is incorporatedby reference here. Briefly, however, the quadrupole LWD tool segment 114includes at least one transmitter ring 200 and an array of receivers212.

FIG. 2 b illustrates a transmitter 200 divided into four quadrants 202,204, 206 and 208. Each quadrant contains a quarter-circle array ofpiezoelectric transducer elements 210. FIG. 2B shows six piezoelectrictransducer elements in each quadrant although in some embodiments nineelements may be preferred uniformly spaced around the azimuth.

As noted above an array of quadrupole receivers 212 is shown in FIG. 2 aembedded within the side wall of drill pipe segment 114. These receiversare equally spaced vertically and may be ten to fifty or more in avertical array. The receivers are similar to the transmitter in thateach receiver 214 of receiver array 212 has a quarter circle ofpiezoelectric transducer elements in each of quadrants 216, 218, 220 and222 as shown in FIG. 2 c. Each ring transducer is capable of detecting aquadrupole shear wave refracted through a formation as discussed morefully in the above referenced Hsu et al publication US 2003/0058739.

While FIGS. 1-2 schematically disclose a LWD system where sonictransmitters and receivers are embedded within the side walls of a drillstring near the drilling bit, FIG. 3 discloses a wireline tool or sonde300 which is lowered down a borehole suspended by a wireline 302following a drill string tripping operation or subsequent loggingfollowing drilling operations. The sonde carries a transmitter 304 andan array of receivers 306 similar to the LWD tool discussed inconnection with FIGS. 1 and 2. In this, the transmitting component 304sends sonic waves 308 into the surrounding earth formation 310 andcompressional or “P” waves 312, shear or “S” waves 314 and Stoneley ortube waves 316 (that are propagated along the interface between aformation and the borehole fluid) are received by an array of thereceiver components 306 as illustrated in FIGS. 2A-2C above.

Measurement of arrivals of these waveforms will show up in aslowness-time plane (STP) as prominent coherent peaks. Thecompressional, shear and Stoneley slowness (DTc, DTs and DTst) will bederived from the attributes of these coherent peaks. The subjectinvention expands the wave component attributes to include coherentenergy (CE) and attenuation (ATT) which are useful in detecting thepresence of formation gas and kick detection.

Waveform Attributes

FIG. 4 depicts a set of synthetic waveforms, as a function of time, asthey appear to an array of receivers placed at equal intervals, 400(RR), along the tool. The abscissa in FIG. 4 is the arrival time ofsonic waves in micro seconds and the ordinate represents sonic receivers1-12. (Equal spacing of receivers (RR) is not a requirement, althoughthis assumption is made here to simplify calculations.) As FIG. 4illustrates, the compressional 402, shear 404, and borehole (orStoneley) 406 wave components generally appear at different times and,because the components differ in “slowness” (S), move out across thearray at different rates.

A waveform arriving at time (T) at the first receiver will arrive at thenth receiver at time (T)+(n−1)·(receiver spacing)·(S). Theslowness-time-coherence (STC) method discussed in Kimball et al.Geophysics, above, is used to process the monopole wireline or LWD sonicwaveform signals for coherent arrivals. This method systematicallycomputes the coherence (C) of signals that start at the first receiverat time (T) and move out across the array at a rate corresponding toslowness (S). All of the coherent arrivals appear in the slowness-timeplane (STP) as prominent coherent peaks. Estimates of compressional,shear, and Stoneley slowness (DTc, DTs, and DTst) are derived from theattributes of these coherent peaks.

For each coherent peak in the S/T plane, the slowness (S) and arrivaltime at the first receiver (T) are used to construct a time window overthe array. One such time window is shown in FIG. 4. The time window isof the same length for each receiver, but, to account for the slowness(S) a time window that begins at time (T) for the first receiver willbegin at time (T)+(n−1)·(receiver spacing)·(S) for the nth receiver. Thelength of the window is the same as the (STC) computation window andconsists of the number equally spaced points within a time window (nptw)at which the waveform is computed.

Let TR(k), k=1, 2, . . . , number of receivers (nrec) be thetransmitter-to-receiver distance for the k-th receiver. Under theassumption of equal spacing, (RR), between adjacent receivers,TR(k+1)−TR(k)=RR, k=1, 2, . . . , nrec−1.

Let w(j,k), j=1, 2, . . . , (nptw), k=1, 2, . . . , (nrec) be thesampled waveform (at the “j”th sampling point and at the “k”th receiver)within the selected time window—“j” represents the time index, and “k”represents the receiver index.

Let hw(j,k) be the (discrete) Hilbert transform of w(j,k) in the timedomain. The analytic representation of the signal, w_(a) (j,k), is acomplex signal defined in terms of w(j,k) and hw(j,k): w_(a)(j,k)=w(j,k)+(i)·(hw(j,k)).

The proposed invention uses the framework described above of definingseveral attributes of the wave components found in the slowness-timeplane (STP). In addition to slowness, time, and coherence, however, thesubject invention demonstrates the utility of coherent energy andattenuation attributes to oil and gas drilling and productionoperations.

Coherent Energy Attribute

The wave component coherent energy attribute (CE) is computed for agiven (S) and (T) in the (STP) by stacking the analytic signals acrossthe array for a given time index “j”, multiplying the result by itsconjugate to get the square of the magnitude for each “j”, and finallyaveraging over the time index “j”. Specifically:

${C\; E} = {\frac{1}{ntpw}{\sum\limits_{j = 1}^{nptw}\left\{ {\left\lbrack {\frac{1}{nrec}{\sum\limits_{k = 1}^{nrec}{w_{a}\left( {j,k} \right)}}} \right\rbrack \times {{conj}\left\lbrack {\frac{1}{nrec}{\sum\limits_{k = 1}^{nrec}{w_{a}\left( {j,k} \right)}}} \right\rbrack}} \right\}}}$

Attenuation Attribute

The wave component attenuation attribute (ATT) is computed for a given(S) and (T) in the (STP) by using a linear least square fit algorithm todetermine how TE(k), the total energy within the time window forreceiver “k”, attenuates as a function of TR(k), the distance from thetransmitter to the kth receiver.

The total energy within the time window for receiver “k”, TE(k), iscomputed using the formula:

${{T\; {E(k)}} = {10 \times {\log_{10}\left\lbrack {\sum\limits_{j = 1}^{nptw}\left\{ {\left\lbrack {w_{a}\left( {j,k} \right)} \right\rbrack \times {{conj}\left\lbrack {w_{a}\left( {j,k} \right)} \right\rbrack}} \right\}} \right\rbrack}}},{k = 1},2,{\ldots \mspace{14mu} {nrec}}$

Here, TE(k) is in a log scale with unit of dB referenced to 1 Pascal.

For the set of real data pairs (TR(k), TE(k)), k=1, nrec, an nth orderleast squares fit polynomial Pn(x)=a₀+a₁x+ . . . +a_(n)x^(n) can beconstructed for n≦nrec−1. This polynomial will minimize:

$\sum\limits_{k = 1}^{nrec}\left( {{P\left( {{TR}(k)} \right)} - {{TE}(k)}} \right)^{2}$

over all polynomials (P) of degree≦n.

The linear least square fit polynomial, P₁(x)=a₀+a₁x, is used here todetermine the attenuation attribute. In particular, the negative valueof the coefficient “a₁” (which is normally negative) will be defined asthe attenuation (ATT).

In the general case of the nth order least square fit polynomial for thedata set {(x_(i), y_(i)), i=1, 2, . . . , N} where N≧n−1, thecoefficient matrix (A) for the polynomial can be obtained from the datapairs by means of the matrix formula:

A = (X^(T)X)⁻¹X^(T)Y  where: $A = \begin{bmatrix}a_{0} \\a_{1} \\\ldots \\\ldots \\a_{n}\end{bmatrix}$ $X = \begin{bmatrix}1 & x_{1} & x_{1}^{2} & \ldots & \ldots & x_{1}^{n} \\1 & x_{2} & x_{2}^{2} & \ldots & \ldots & x_{2}^{n} \\\ldots & \ldots & \ldots & \ldots & \ldots & \ldots \\\ldots & \ldots & \ldots & \ldots & \ldots & \ldots \\1 & x_{N} & x_{N}^{2} & \ldots & \ldots & x_{N}^{n}\end{bmatrix}$ $Y = \begin{bmatrix}y_{1} \\y_{2} \\\ldots \\\ldots \\y_{N}\end{bmatrix}$

For the linear least square fit polynomial where n=1, this formula forthe coefficients reduces to:

$a_{0} = \frac{{\sum\limits_{i = 1}^{N}{x_{i}^{2}{\sum\limits_{i = 1}^{N}y_{i}}}} - {\sum\limits_{i = 1}^{N}{x_{i}{\sum\limits_{i = 1}^{N}{x_{i}y_{i}}}}}}{{N{\sum\limits_{i = 1}^{N}x_{i}^{2}}} - \left( {\sum\limits_{i = 1}^{N}x_{i}} \right)^{2}}$and$a_{1} = \frac{{N{\sum\limits_{i = 1}^{N}{x_{i}y_{i}}}} - {\sum\limits_{i = 1}^{N}{x_{i}{\sum\limits_{i = 1}^{N}y_{i}}}}}{{N{\sum\limits_{i = 1}^{N}x_{i}^{2}}} - \left( {\sum\limits_{i = 1}^{N}x_{i}} \right)^{2}}$

For the particular application involving attenuation, as describedabove, N=nrec; x_(i)=TR(i), the distance between the transmitter and the“i”th receiver; and y_(i)=TE(i), the total energy at the “i”th receiver.

Where: (ATT), the attenuation, =−a₁

Gas Zone Detection

Gas, even in trace amounts, affects certain wave components such ascompressional waves and Stoneley waves. Accordingly, the attributes ofthe sonic wave components discussed above can be used to detect thepresence of gas in the formation in real time.

When a drill bit penetrates a gas-bearing formation with unexpected highpressure (higher than the mud pressure), gas may seep into the wellbore. The sonic tool, which may be 50 to 100 feet behind the drill bit,can provide the data needed to determine the attributes of the sonicwave components and can, therefore, provide a driller with nearreal-time detection of gas zones. This information will, for example,help the driller choose an appropriate mud weight so that the formationgas does not continually seep into the borehole. Alternatively, if themud weight has to be lower for other drilling reasons, the driller couldset pipe to protect the borehole from a gas zone.

Since gas will travel with the circulating mud uphole immediately,Stoneley (ST) waves, as detected by the sonic tool, will be affected bythe presence of gas in the borehole well before the sonic tool reachesthe gas zone. Thus, the attributes of the Stoneley waves may be thefirst indicators of gas in the formation. Gas, even a trace amount, isknown to slow down and attenuate tremendously the Stoneley wave in theborehole over the sonic logging frequency range. The slowness (DT),coherent energy (CE), and the attenuation (ATT) attributes of theStoneley wave components can be monitored as a function of depth toprovide early detection of the presence of gas in a borehole.

The attributes of compressional (C) and shear (S) waves can also be usedto detect the presence of gas. Like the Stoneley waves, compressionalwaves are known to slow down and attenuate tremendously in the presenceof a small amount of gas. On the other hand, the slowness andattenuation of the shear wave changes relatively little in the presenceof gas.

FIG. 5 illustrates how compressional and shear waveform attributes canbe used to detect a gas zone. The three graphs in FIGS. 5 a, 5 b and 5 cshow how the different attributes (slowness, attenuation, and coherentenergy) are affected by the presence of gas. The three patterns ofvariation can be used to corroborate each other in identifying thepresence of gas.

In the gas zone, DTc 500 increases rapidly, while the change in DTs 502is relatively minor (FIG. 5 a). This results in a significant increasein the ratio DTc/DTs (or as shown in FIG. 5 a a significant decrease inits reciprocal (Vp/Vs 504) decrease in the compressional to shearvelocity as the tool moves down the hole. If DTc increases due tolithology changes, as opposed to the presence of gas, Dts will alsoincrease and the velocity ratio Vp/Vs is also likely to increase.

Normally, in formations without gas, the attenuation associated withshear waves, (ATTs) 506, is slightly higher than the attenuationassociated with compressional waves, (ATTc) 508 (FIG. 5 b). Gas causesATTc to increase more rapidly than ATTs, resulting in a crossover of thetwo curves—note point 510 in FIG. 5 b and the ratio ATTc/ATTs willincrease.

The coherent energy attribute of compressional waves, (CEc) 512, willalso show a much greater rate of decrease than the coherent energyattribute of shear waves, (CEs) 514 (see FIG. 5 c) in the presence ofgas. Thus the ration CEC/CES will decrease.

Data from the compressional and shear wave attributes as a function ofdepth or time, as depicted in FIGS. 5 a-5 c, can be used to set atrigger level or gas zone flag that is sent uphole to warn the drillerof entry into a gas bearing formation. As an example, an alert could betriggered when the baseline Vp/Vs ratio decreases below a certain value.Increases in (DTc) and behavior of DTc/DT_(s), ATTc, ATTs, ATTc/ATTs,CEc, CEs and CEc/CEs, consistent with FIGS. 5 a-5 c, could be used tosubstantiate the presence of gas.

Kick Detection

A sudden infusion of fluid or gas within a borehole is known as kick.Stoneley wave attributes (DTst, ATTst, and CEst) are particularlysensitive indicators for the presence of gas in the well bore.Accordingly they can be used on a real time basis as incipient kickindicators to provide a driller with valuable reaction time for safedrilling of a well. The added reaction time provided by the Stoneleywave attributes, as opposed to compressional and shear wave attributes,may significantly increase drilling safety.

The Stoneley slowness (DTst), attenuation (ATTst), and amplitude (CEst)are functions of the mud and formation properties. When drilling throughformations of the same lithology, the variation in these Stoneley waveattributes are sensitive indicators of kick of gas or formation fluid.Normally, these attributes will be very slowly changing variables withina given zone of the same lithology. Their baseline values, as a functionof time or well depth, can be established by other LWD measurementtechniques such as gamma ray (GR), sonic delta-t, resistivity andnuclear tools. Any abrupt changes in the attributes may signify thepossible influx of gas or formation fluids and will, therefore, triggera warning flag.

FIGS. 6 a-6 c illustrate how Stoneley wave attributes can be used toconstruct a kick warning flag. In FIG. 6 a, the lithology of the zone ofinterest is shown to be essentially uniform, as verified by sonicdelta-t logs (DTc 600 and DTs 602) and (GR 604) logs. These logs arecontrolled primarily by properties of the formation, while the Stoneleywave slowness, (DTst), is also sensitive to the borehole and mudproperties. A sudden change in (DTst) in the uniform formation zone ofFIG. 6 a usually implies significant influx of gas or formation fluid.An influx of gas will cause (DTst) to increase drastically (note 606 inFIG. 6 a) while an influx of connate water will usually cause (DTst) todecrease somewhat (note 608 in FIG. 6 a).

In order to detect a sudden change in Stoneley slowness due to an influxof gas or fluid, it may be advantageous to monitor the ratio (DTst/DTs),which can normalize some variation in (DTst) due to changes in theproperties of the formation. FIG. 6 b depicts an increase of the ratio(DTst/DTs) 610 as compared with its baseline ratio, which is due to aninflux gas. FIG. 6 b also depicts a decrease of the ratio (DTst/DTs) 612as compared with its baseline, which is due an influx in formationfluid. It suggests that a trigger level for this ratio would betypically a certain fractional increase or decrease relative to thebaseline of the (DTst/DTs) ratio.

FIG. 6 c shows that an influx of gas will result in a significantincrease in (ATTst) 614, while (CEst) 616 will experience a rapiddecrease. An influx of fluid will usually cause (ATTst) to decreaseslightly (note 618), while (CEst) may increase somewhat (note 620).(ATTst) and (CEst) can, therefore, provide corroboration to a warningtriggered by changes in the (DTst/DTs) ratio.

Change detection logic can be used to set change flags (CFs) based on agiven type of input that is continually generated as a tool proceedsdown the borehole. FIGS. 7 and 9 are illustrative diagrams, based on thechange detection logic described here, for gas zone detection and kickdetection, respectively. Input used in the illustrative charts include:

Gamma Ray measurement (GR)

Coherent Energy ratio for compressional and shear waves (R_(CE))

Attenuation ratio for compressional and shear waves (R_(ATT))

Slowness ratio for compressional and shear waves (R_(DT))

Coherent Energy for Stoneley waves (CE_(ST))

Attenuation for Stoneley waves (ATT_(ST))

Slowness for Stoneley Waves (DT_(ST))

The inputs involving compressional and shear waves are primarily usefulin formation gas zone detection while the inputs involving Stoneleywaves are primarily useful in kick detection. Gamma ray measurementscould be used in both gas zone and kick detection, but are most usefulin gas zone detection, since the Stoneley waves reacts almostimmediately to a small amount of gas released to the borehole fluid atthe bit. The gamma ray input will be particularly helpful for kickdetection if the gamma ray sonde is very near or inside the bit.

A Change Flag for a given type of input can take on the values 1, −1, or0, corresponding, respectively, to the input exhibiting a largeincrement, a large decrement, or no change, relative to previousmeasurements. A driller needs to determine how much past data is storedfor comparison and how large an increment or decrement over earlier datais required to assign the flag a value of 1 or −1.

If (N) represents the (user-chosen) amount of previous input data thatis maintained for comparison. The most recent (N) inputs are placed in abuffer that maintains a running average (M)—the most recent (N) inputsare added and the result is divided by (N) to determine (M) at any giventime. In the start-up period when the buffer is not full, (M) will bethe average over the inputs that have been recorded.

A driller chosen number (D) represents the number that will be used todetermine if a significant change has occurred. The most recent input(X) is compared with (M), the running average in the buffer. If (X−M>D),(CF) is set to 1 indicating a large increment in the particular inputdata. If (X−M<−D), (CF) is set to −1 indicating a large decrement in theparticular input data. If |X−M|≦(D), (CF) is set to 0 indicating nosignificant change in the input data.

The (N) and (D) will likely be different for the different kinds ofinput and thus are subscripted as (N_(in)) and (D_(in)) for genericindex in.

Flow Diagram for Attributes Gas Zone Detection

In FIG. 7 gas zone detection flags are used to detect gas-containingformations in the vicinity (˜100 feet behind the bit) of the sonic tool.The gas in the formation may or may not seep out into the well boredepending on the mud weight and the bottom hole pressure. Thus, Stoneleyor borehole waves may not provide instantaneous detection at the tool.Thus, this flow diagram exploits the changes—particular the relativechanges—in coherent energy (CE), attenuation (ATT) and slowness (DT) ofthe compressional and shear waves to the presence of gas in theformation.

Unfortunately, the responses of the compressional and shear waves alsovary with lithology or rock type. Lithology change is reflectedindependently using gamma ray measurement and this measurement is usedto minimize false alarms triggered by changes in the compressional andshear waves due to lithology.

Change detection, as described in the “Change Detection Logic” discussedabove, relies on the following input data and derived ratios:

-   -   Gamma Ray measurement (GR)—box 702;    -   Coherent Energy ratio for compressional and shear waves        (R_(CE)=CEc/CEs)—boxes 700 and 704;    -   Attenuation ratio for compressional and shear waves        (R_(ATT)=ATTc/ATTs) boxes 700 and 706; and    -   Slowness ratio for compressional and shear waves        (R_(DT)=DTc/DTs) boxes 700 and 708.

Each of the four types of input has its own selected (N) (number ofretained data points or the size of the data buffer) and (D) (thedifference between the buffer average (M) and the most recent input datathat will trigger a change flag for the type of input). The change flags(CFs) for the four types of input (each with value 1, −1, or 0) 710,712, 714 and 716 are used to compute the value of the Gas Zone Flag 718,which may then trigger a response by the driller to suspected gas in theformation. The computation of this value may also involvedriller-supplied weights. To get a correct result, the weights assignedto the flags for the slowness and attenuation ratios (R_(DT) andR_(ATT)) will be positive, and the weight assigned to the flag for thecoherent energy ratio (R_(CE)) will be negative. The flag associatedwith gamma ray measurement may be incorporated as a separate term or afactor of the form: [1−abs (CF_(GR))] in order to help eliminate settinga gas flag when changes are due to lithology.

The Gas zone Flag (GF) in FIG. 7 behaves like a switch on state changeindicator. If the attributes respond to the onset of gas, GF would beexpected to increase from zero to a positive value depending on theweighting factors and the number of corresponding indicators. If theattributes remain unchanged, there will be no change in GF, whether gasis present or not present. If the sonic tool moves away from a gas zone,GF would take on a negative value signifying the disappearance of gas.

The Gas Flag (GF) should be used in conjunction with a gas responseindicator (GRI) which may be a combination of the basic attributes. Thefollowing are some examples of GRI that will have higher values in a gaszone.

GRI=ATTc/ATTs*DTc/DTs*CEs/CEc

GRI=(DTc*ATTc)/CEc

GRI=Att*ATTc/ATTs+Wdt*DTc/DTs+Wce*CEs/CEc

where Watt, Wdt and Wce are nonnegative weighting coefficients.

FIG. 8 illustrates the relationship between the Gas Flag 800 (GF) whichis a state change indicator and Gas Response Indicator (GRI) 802 whichtakes on larger values when gas is present than when it is absent. Thetwo indicators would be used in combination to inform the decision makerof the presence of a gas zone.

Flow Diagram for Sonic Attributes Kick Detection

In FIG. 9 kick detection flags are used to detect a small amount of gasreleased to the borehole fluid from the formation at the bit and,therefore, provide early warning time to a driller. Stoneley or boreholewaves, which exhibit predictable changes in coherent energy, attenuationand slowness in this situation, provide the primary method of detection.

Change detection, as described in the “Change Detection Logic” above,uses the following input data:

Gamma Ray measurement (GR)—box 900;

Coherent Energy for Stoneley waves (CE_(ST))—box 902;

Attenuation for Stoneley waves (ATT_(ST))—box 902; and

Slowness for Stoneley Waves (DT_(ST))—box 902.

Each of the four types of input has its own selected (N) (number ofretained data points or the size of the data buffer) and (D) (thedifference between the buffer average (M) and the most recent input datathat will trigger a change flag for the type of input). The change flags(CFs) for the four types of input (each with value 1, −1, or 0) 904,906, 908 and 910 are used to compute the value of a Kick Detection Flag912, which may then trigger a response by the driller to suspected gasat the drill bit. The computation of this value will probably involvedriller-supplied weights. To get the correct result, the weightsassigned to the flags for Stoneley slowness and attenuation (DTst andATTst) will be positive, and the weight assigned to the flag for thecoherent energy (CEst) will be negative. A flag associated with gammaray measurement may be incorporated as a separate term or a factor ofthe form: [1−abs (CF_(GR))] if the gamma ray sonde is very near thedrill bit.

The Kick detection Flag (KF) in FIG. 9 behaves like a switch or statechange indicator. As with the Gas zone Flag (GF) in FIG. 7, this flagshould be used in conjunction with a Gas Response Indicator (GRI). Inthis case, some examples of a GRI based on the attributes of Stoneley orborehole waves are:

GRI=(ATTst*DTst)/CEst

GRI=Watt*ATTst+Wdt*DTst+Wce/CEst

where Watt, Wdt and Wce are nonnegative weighting coefficients.

FIG. 10 illustrates the relationship between the Kick detection Flag(KF) 1000 and the Gas Response Indicator) GRI) 1002, which takes onlarger values when kick is imminent. The two indicators are used incombination to inform a driller of the possibility of a kick event.

The various aspects of the invention were chosen and described in orderto best explain principles of the invention and its practicalapplications. The preceding description is intended to enable those ofskill in the art to best utilize the invention in various embodimentsand aspects and with modifications as are suited to the particular usecontemplated. It is intended that the scope of the invention be definedby the following claims.

What is claimed is:
 1. A method for determining the presence of aformation gas kick on a real time basis by a logging while drillingprocess comprising: emitting periodic sonic wave energy toward aborehole formation by a logging while drilling tool; receiving Stoneleywaveform signals transmitted within the borehole; determining thelithology of formations as drilling progresses; determining the Stoneleywave slowness (DTst) within the well bore; and for an essentiallyuniform formation lithology determining the presence of gas kick withinthe borehole by a sudden change at different depths in Stoneley slowness(DTst) over formations with essentially similar lithology.
 2. A methodfor determining the presence of a formation gas kick on a real timebasis by a logging while drilling process as defined in claim 1 andfurther comprising: determining the Stoneley wave attenuation (ATTst)within the well bore; and for an essentially uniform formation lithologyconfirming the presence of a gas kick within the borehole by a suddenincrease in Stoneley attenuation (ATTst).
 3. A method for determiningthe presence of formation gas kick on a real time basis by a loggingwhile drilling process as defined in claim 1 and further setting as gaskick flag comprising: detecting a change in the Stoneley slowness(DTst); and setting a kick flag to warn a driller of the drillingoperation encountering a formation gas kick in the event the detectedchange in (DTst) exceeds a set value.
 4. A method for determining thepresence of a formation gas kick on a real time basis by a logging whiledrilling process as defined in claim 1 and further comprising:determining the Stoneley wave coherent energy (CEst) within the wellbore; and for an essentially uniform formation lithology confirming thepresence of a gas kick within the borehole by a sudden decrease inStoneley coherent energy (CEst).
 5. A method for determining thepresence of a formation gas kick on a real time basis by a logging whiledrilling process as defined in claim 4 and further comprising: detectinga change in one or more Stoneley attributes of (DTst, ATTst and CEst)and prior to setting a kick detection flag assigning a weighting factorto one or more of the Stoneley attributes (DTst, ATTst and CEst).
 6. Amethod for determining the presence of a formation gas kick on a realtime basis by a logging while drilling process comprising: emittingperiodic sonic wave energy toward a borehole formation by a loggingwhile drilling tool; receiving Stoneley waveform signals transmittedwithin the borehole; determining the lithology of formations as drillingprogresses; determining the Stoneley wave attenuation (ATTst) within thewell bore from the attributes of received coherent Stoneley waveformsignal peaks; and for an essentially uniform formation lithologydetermining the presence of gas kick within the borehole by a suddenchange at different depths in Stoneley wave attenuation (ATTst) overformations with essentially similar lithology.
 7. A method fordetermining the presence of a formation gas kick on a real time basis bya logging while drilling process as defined in claim 6 and furthercomprising: determining the Stoneley wave coherent energy (CEst) withinthe well bore; and for an essentially uniform formation lithologyconfirming the presence of a gas kick within the borehole by a suddendecrease in Stoneley coherent energy (CEst).
 8. A method for determiningthe presence of formation gas kick on a real time basis by a loggingwhile drilling process as defined in claim 6 and further setting as gaskick flag comprising: detecting a change in the Stoneley attenuation(ATTst); and setting a kick flag to warn a driller of the drillingoperation encountering a formation gas kick in the event the detectedchange in (ATTst) exceeds a set value.
 9. A method for determining thepresence of a formation gas kick on a real time basis by a logging whiledrilling process comprising: emitting periodic sonic wave energy towarda borehole formation by a logging while drilling tool; receivingStoneley waveform signals transmitted within the borehole; determiningthe lithology of formations as drilling progresses; determining theStoneley wave coherent energy (CEst) within the well bore; and for anessentially uniform formation lithology determining the presence of gaskick within the borehole by a sudden change in Stoneley coherent energy(CEst) over formations with essentially similar lithology.
 10. A methodfor determining the presence of formation gas kick on a real time basisby a logging while drilling process as defined in claim 9 and furthersetting as gas kick flag comprising: detecting a change in the Stoneleycoherent energy (CEst); and setting a kick flag to warn a driller of thedrilling operation encountering a formation gas kick in the event thedetected change in (CEst) exceeds a set value.